Recent discoveries of High Pressure High Temperature (HPHT) oil and gas reserves in the Gulf of Mexico and the North Sea presented a significant challenge to subsea production technologies, and especially for production control. Most significantly, while the pressure differences at early production are estimated to be around 5000 psi or even higher, they are expected to substantially decrease over time. Such anticipated pressure gradient is difficult to manage in a safe and economic manner using currently known technology.
Therefore, reliable and adjustable subsea chokes are essential to address at least some of the problems associated with subsea production systems. In most currently known cases, a single subsea production choke is mounted on a subsea production tree, which is the main control device to adjust the flow rate from a well. Depending on the type of fluid conveyed (sour/sweet service) and pressure encountered, appropriate materials and configurations can be selected to improve performance and lifetime. Unfortunately, as the excess pressure in HPHT wells may be higher than 5000 psi across the production choke, rapid deterioration or even failure of the choke is likely due to high-velocity erosion at the choke trim (e.g., at very small opening, the flow area is relatively small and the fluids velocity is high. Moreover, changes from one phase to two phases further promote erosion, abrasion, and cavitation). To overcome at least some of these difficulties, dual-choke configurations may be implemented as described in our co-pending International application, published as WO 2008/045381, which is incorporated by reference herein. While such configurations and methods advantageously improve handling of relatively high pressure differentials and extend lifetime of the chokes, several drawbacks nevertheless remain.
For example, high wellhead pressures often require specific allocation measurements due to the vast network of production flow lines, risers, and subsea pipelines. For example, in the Gulf of Mexico, these systems are laid throughout valleys and drop offs, which tend to create void spots were produced water builds up. As a result, slug flows are common among these developments and often require large slug catcher systems. Furthermore, since effective choking is critical to apply HIPP (High Integrity Pressure Protection System) systems to the subsea pipeline, the choke is typically required to set the pressure at the inlet well below the design pressure to allow for flow transients and to provide sufficient time for a HIPPS valve to close in the event of a pressure increase due to blockage. As currently known choke valve systems fail to be responsive to fluid composition and changes thereof, pressure and flow control remains difficult in production, and especially subsea production.
To overcome at least some of the difficulties associated with flow control in subsea systems, various attempts have been made. For example, temperature and/or pressure can be measured at a point upstream of a location where a slug is generated as described in WO 02/46577. A dynamic feedback controller then calculates from the temperature or pressure measurement an appropriate setting for an output valve that is downstream of the temperature of pressure sensor. Alternatively, slug flow is controlled by a throttling valve in the flowline upstream of a gas-liquid separator and a differential pressure gauge that is used to measure the presence and the volume of the slug in the flowline (see e.g., U.S. Pat. No. 5,544,672). Similarly, U.S. Pat. No. 7,434,621 describes a system with a slug catcher or phase separator where a slug detector is located downstream of the point of slug initiation and upstream of the catcher or separator. Here, a computer unit is integrated into the flow line system and the downstream process to determine the type and volume of the slug and to predict its arrival time into the downstream process. While such systems will in some instances allow for at least partial automation of flow control, currently known systems tend to be unsuitable for use in HTHP wells and complex flow paths. Moreover, most known control systems to prevent or reduce slug flow suffer from significant lag between measurement and corrective action.
Therefore, while numerous configurations and methods of production control are known in the art, all or almost all of them suffer from one or more disadvantages. Thus, there is still a need to provide improved configurations and methods of production control, and particularly production well control.